Model for a Shale-Gas Formation With Salt-Sealed Natural Fractures

Most multiple-transverse-fracture horizontal wells in shale-gas formations remain in transient bilinear or linear flow for very long periods. However, there are often reported cases of shale wells that exhibit boundary-dominated flow in a very short period, which implies a stimulated rock volume (SRV) much smaller than would be expected. This paper offers an alternative explanation for the early boundary-dominated flow related to dissolution of salt-sealed natural fractures in the shale.

Introduction

Operators producing gas from the Haynesville, Marcellus, and Horn River shale formations have observed that produced water is more saline than the injected fracturing fluid. Additionally, the fraction of injected water that flows back when the well is put on production—termed load recovery—is low.

This study investigates the possibility that salts removed by flowing back injected low-salinity water-based fracturing fluid may be a mechanism for increasing the effective permeability in shale-gas wells within a limited volume surrounding the created hydraulic fractures. The study offers strong evidence that salt may be a key factor in productivity and ultimate gas recovery from shale-gas wells.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 175061, “Model for a Shale-Gas Formation With Salt-Sealed Natural Fractures,” by Hoagie Merry and C.A. Ehlig-Economides, University of Houston, and Pang Wei, Sinopec Research Institute of Petroleum Engineering, prepared for the 2015 SPE Annual Technical Conference and Exhibition, Houston, 28–30 September. The paper has not been peer reviewed.

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